This invention relates in general to heat exchangers and, more particularly, to a process and apparatus for detecting condensation in a heat exchanger.
Natural gas represents a significant source of electrical energy in the United States. It burns with few emissions, and is available throughout much of the country. Moreover, the plants which convert it into electrical energy are efficient and, in comparison to hydroelectric projects and coal-fired plants, they are relatively easy and inexpensive to construct. In the typical plant, the natural gas burns in a gas turbine which powers an electrical generator. The exhaust gases—essentially carbon dioxide and steam—leave the gas turbine at about 1200° F. (649° C.) and themselves represent a significant source of energy. To harness this energy, the typical combined cycle, gas-fired, power plant also has a heat recovery steam generator (HRSG) through which the hot exhaust gases pass to produce steam which powers a steam turbine which, in turn, powers another electrical generator. The exhaust gases leave the HRSG at temperatures on the order of 150° F. (66° C.).
The HRSG basically comprises a series of heat exchanges housed in a duct. Water which is derived from condensing steam discharged from the steam turbine enters the HRSG at a feedwater heater where it undergoes a rise in temperature. The higher temperature water then flows into an evaporator where it is converted into steam, most if not all saturated steam. That steam flows into a superheater which converts it into superheated steam, and the superheated steam flows on to the steam turbine to power it. The hot gases derived from the combustion flow in the opposite direction, encountering the superheater, then the evaporator, and finally the feedwater heater.
Thus, the gases are at their coolest temperatures in the region of the feedwater heater and beyond. Natural gas contains traces of sulfur, and during the combustion the sulfur combines with oxygen to produce oxides of sulfur. Moreover, the combustion produces ample quantities of water in the form of steam. If the exhaust gases remain above the dew point for the gases, which is about 107° F. (42° C.), the oxides of sulfur pass out of the HRSG and into a flue. However, the low temperature feedwater has the capacity to bring the tubes at the downstream end of the feedwater heater below the dew point of the water in the exhaust gases, and when this occurs, water condenses on tubes. The oxides of sulfur in the flue gas unite with that water to form sulfuric acid which is highly corrosive. Other acids may likewise form.
In order to deter the formation of acids, operators of HRSGs control the temperature of the water entering the feedwater heater, so that it remains well above the dew point for the gases. This assures that no condensation occurs in the feedwater heater. And to be safe, the temperature of the entering water needs to be high, because the dew point temperature of the gases is difficult to predict in that it is a function of several parameters. If the temperature of the entering water could be lowered, the water would extract more energy from the gases, and they would pass beyond the feedwater heater at a lower temperature.
The problem of condensation in feedwater heaters or economizers is not confined solely to HRSGs installed downstream from gas turbines. Indeed, it can occur almost anywhere energy is extracted from hot gases flowing though a duct to heat the feedwater for a boiler. For example, many power plants convert the hot gases derived from the combustion of fossil fuels, such as coal or oil, directly into steam, and the boilers required for the conversion, to operate efficiently, should have feedwater heaters—heaters which should not produce condensation. Also, systems exist for producing steam from the hot gases derived from the incineration of waste, and they likewise have boilers including feedwater heaters that should not be subjected to condensation.